|Publication number||US7417920 B2|
|Application number||US 11/136,147|
|Publication date||Aug 26, 2008|
|Filing date||May 24, 2005|
|Priority date||Mar 13, 2001|
|Also published as||CA2609129A1, US20050260089, WO2006127760A1|
|Publication number||11136147, 136147, US 7417920 B2, US 7417920B2, US-B2-7417920, US7417920 B2, US7417920B2|
|Inventors||Detlef Hahn, Volker Peters, Cedric Rouatbi, Eckard Scholz|
|Original Assignee||Baker Hughes Incorporated|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (31), Referenced by (17), Classifications (21), Legal Events (2)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application is a Continuation-In-Part of prior application Ser. No. 10/096,451, filed Mar. 12, 2002, now U.S. Pat. No. 6,898,150, which claims the benefit of U.S. Provisional Application No. 60/275,342 filed on Mar. 13, 2001, both of which are incorporated herein by reference.
1. Field of the Invention
The present invention relates to drilling fluid telemetry systems and, more particularly, to a telemetry system incorporating a reciprocating pulser system for modulating the pressure of a drilling fluid circulating in a drill string within a well bore.
2. Description of the Related Art
Drilling fluid telemetry systems, generally referred to as mud pulse systems, are particularly adapted for telemetry of information from the bottom of a borehole to the surface of the earth during oil well drilling operations. The information telemetered often includes, but is not limited to, parameters of pressure, temperature, direction and deviation of the well bore. Other parameters include logging data such as resistivity of the various layers, sonic density, porosity, induction, self potential and pressure gradients. This information is critical to efficiency in the drilling operation.
The oil drilling industry needs to effectively increase mud pulse data transmission rates to accomodate the ever increasing amount of measured downhole data. The major disadvantage of available mud pulse valves is the low data transmission rate. Increasing the data rate with available valve types leads to unacceptably large power consumption, unacceptable pulse distortion, or may be physically impractical due to erosion, washing, and abrasive wear. Because of their low activation speed, nearly all existing mud pulse valves are only capable of generating discrete pulses. To effectively use carrier waves to send frequency shift (FSK) or phase shift (PSK) coded signals to the surface, the actuation speed must be increased and actuation fully controlled.
Mud pulse valves, also called pulsers, must operate under extremely high static downhole pressures, high temperatures, high flow rates and various erosive flow types. At these conditions, the valve must be able to create pressure pulses of around 100-300 psi.
Different types of valve systems are used to generate downhole pressure pulses. Valves that open and close a bypass from the inside of the drill string to the wellbore annulus create negative pressure pulses, for example see U.S. Pat. No. 4,953,595. Valves that use a controlled restriction placed in the circulating mud stream are commonly referred to as positive pulse systems, for example see U.S. Pat. No. 3,958,217.
Another example of a negative pulsing valve is illustrated in U.S. Pat. No. 4,351,037. This technology includes a downhole valve for venting a portion of the circulating fluid from the interior of the drill string to the annular space between the pipe string and the borehole wall. Drilling fluids are circulated down the inside of the drill string, out through the drill bit and up the annular space to surface. By momentarily venting a portion of the fluid flow out a lateral port, an instantaneous pressure drop is produced and is detectable at the surface to provide an indication of the downhole venting. A downhole instrument is arranged to generate a signal or mechanical action upon the occurrence of a downhole detected event to produce the above described venting. The downhole valve disclosed is defined in part by a valve seat, or nozzle, having an inlet and outlet and a valve stem movable to and away from the inlet end of the valve seat in a linear path with the drill string.
All negative pulsing valves need a certain high differential pressure below the valve to create sufficient pressure drop when the valve is open. Because of this high differential pressure, negative pulse valves are more prone to washing. In general, it is not desirable to bypass flow above the bit into the annulus. Therefore it must be ensured that the valve is able to completely close the bypass. With each actuation, the valve hits against the valve seat. Because of this impact, negative pulsing valves are more prone to mechanical and abrasive wear than positive pulsing valves.
Positive pulsing valves might, but do not need to, fully close the flow path for operation. Positive poppet type valves are less prone to wear out the valve seat. The main forces acting on positive poppet valves are hydraulic forces, because the valves open or close axially against the flow stream. To reduce the actuation power some poppet valves are hydraulically powered as shown in U.S. Pat. No. 3,958,217. Hereby the main valve is indirectly operated by a pilot valve. The low power consumption pilot valve closes a flow restriction, which activates the main valve to create the pressure drop. The power consumption of this kind of valve is very small. The disadvantage of this valve is the passive operated main valve. With high actuation rates the passive main valve is not able to follow the actively operated pilot valve. The pulse signal generated is highly distorted and hardly detectable at the surface.
Commonly, rotating disc valves open and close flow channels perpendicular to the flow stream, such that thrust bearings support a portion of the hydraulic forces. With increasing actuation speed, dynamic forces of inertia are the main power consuming forces. U.S. Pat. No. 3,764,968 describes a rotating valve for the purpose to transmit frequency shift key (FSK) or phase shift key (PSK) coded signals. The valve uses a rotating disc and a non-rotating stator with a number of corresponding slots. The rotor is continuously driven by an electrical motor. Depending on the motor speed, a certain frequency of pressure pulses are created in the flow as the rotor intermittently interrupts the fluid flow. Motor speed changes are required to change the pressure pulse frequency to allow FSK or PSK type signals. There are several pulses per rotor revolution, corresponding to the number of slots in the rotor and stator. To change the phase or frequency requires the rotor to increase or decrease in speed. This may take a rotor revolution to overcome the rotational inertia and to achieve the new phase or frequency, thereby requiring several pulse cycles to make the transition. Amplitude coding of the signal is inherently not possible with this kind of continuously rotating device. In order to change the frequency or phase, large moments of inertia, associated with the motor, must be overcome, requiring a substantial amount of power. When continuously rotated at a certain speed, a turbine might be used or a gear might be included to reduce power consumption of the system. On the other hand, both options dramatically increase the inertia and power consumption of the system when changing form one to another speed for signal coding.
The aforesaid examples illustrate some of the critical considerations that exist in the application of a fast acting valve for generating a pressure pulse. Other considerations in the use of these systems for borehole operations involve the extreme impact forces, dynamic (vibrational) energies, existing in a moving drill string. The result is excessive wear, fatigue, and failure in operating parts of the system. The particular difficulties encountered in a drill string environment, including the requirement for a long lasting system to prevent premature malfunction and replacement of parts, require a robust and reliable valve system.
The methods and apparatus of the present invention overcome the foregoing disadvantages of the prior art by providing a novel mud pulse telemetry system utilizing a reciprocating poppet type valve.
The present invention contemplates a mud pulse telemetry system utilizing a reciprocating pulser system for generating pressure pulses in the drilling fluid circulating in a drill string in a well bore.
In one aspect, a method of transmitting pressure pulses from a downhole location through a flowing fluid in a wellbore, comprises using a linear actuator to controllably move a reciprocating member axially back and forth between a first position and a second position to at least partially obstruct flow of the flowing fluid to generate the pressure pulses.
In another aspect, a reciprocating pulser for generating pressure pulses in a fluid flowing in a wellbore, comprises a fluid passage that allows flow of the fluid through the pulser, and a reciprocating member. A linear actuator is coupled to the reciprocating member, such that the linear actuator moves the reciprocating member in a first axial direction and then in a reverse direction to at least partially obstruct flow of the fluid through the pulser to generate pressure pulses in the flowing fluid.
Examples of the more important features of the invention thus have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto.
For detailed understanding of the present invention, references should be made to the following detailed description of the embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:
FIGS. 9A,B are sketches of a pulser system having a spring assist for poppet extension according to one embodiment of the present invention;
A reciprocating member, such as poppet 103, is attached to the shaft 106 and is axially driven by the linear motor 104 in a reciprocating motion. The poppet 103 is positioned such that at one end of the reciprocating motion, also called travel or stroke, the poppet 103 is in close proximity to the main nozzle 125 opening, thereby restricting the flow through the main nozzle 125 and generating an increase in the upstream pressure. The poppet 103 is then driven away from the main nozzle 125 to the other end of the reciprocating motion which results in a decrease in the upstream pressure. The reciprocating motion thereby generates pressure fluctuations, or pulses, in the drilling fluid 31. The motor 104 is contained in and attached to the bearing housing 108. The shaft 106 is attached to the motor 104 and supported by oil-lubricated bearings 109 at each end of the bearing housing 108. The bearings 109 may be linear sleeve type bearings or, alternatively, linear ball bushings. The bearing housing 108 is attached to the support ring 130 and the support ring is, in turn, attached to the tool housing 101. The support ring 130 has a number of holes or slots to allow the drilling fluid 31 to pass through. Linear motor 104 comprises a magnet carrier 135 attached to the shaft 106 with a coil 140 of electrical wire mounted on the inner diameter of the bearing housing 108 and surrounding the magnet carrier 135. The magnet carrier 135 and the coil 140 are sized so that the magnet carrier is able to freely move within the coil 140 and there is no physical interference between them. An electronics module 145 provides electrical signals to the coil 140 to accurately drive the magnet carrier-shaft-poppet combination in a linearly oscillating motion. Henceforth in this discussion, motion of the poppet is taken to mean motion of the magnet carrier 135-shaft 106-poppet 103 combination. Linear electric motors are commercially available and will not be discussed further. The electronics module 145 contains a processor and suitable circuitry, acting according to programmed instructions, which provide control signals to the linear motor. A linear motion measuring sensor (not shown) is located inside the linear motor 104 and provides position measurement to the electronics module 145 to facilitate feedback control of the motion of the poppet 103.
The entire pulser housing 108 is filled with appropriate lubricant 111 to lubricate the bearings 109 and to pressure compensate the internal pulser housing 108 pressure with the downhole pressure of the drilling mud 31. The seal 107 is a flexible bellows seal directly coupled to the shaft 106 and the pulser end cap 150 and hermetically seals the oil filled pulser housing 108. The linear movement of the shaft 106 causes the flexible material of the bellows seal 107 to deform thereby accommodating the linear motion. The flexible bellows material may be an elastomeric material or, alternatively, a fiber reinforced elastomeric material. Alternatively, a flexible metal bellows may be used.
In contrast to a rotating pulser valve, the hydraulic forces acting on an axially reciprocating pulser valve are more dependent on the pressure drop across the pulser valve. The pressure drop across the pulser valve is directly proportional to the fluid properties, typically density and viscosity, the fluid flow rate, and inversely proportional to the flow area through the nozzles, main 125 and bypass 115. To compensate these hydraulic forces, a force balancing spring 105 is disposed between the end cap 150 and the magnet carrier 135. The spring force is used to offset the hydraulic forces at a nominal operating flow rate. For example,
Downhole tools, including pulser valves, must operate over a range of flow rates and fluid properties. For example, with a constant flow area, as the flow rate and/or fluid viscosity or fluid density are increased, the pressure drop will increase, and hence the hydraulic forces acting on the poppet will increase thereby changing the desired balance of forces on the poppet 103. In order to provide for these operational changes, at least one of the bypass nozzles 115 has a bypass poppet 160, see
The electronics module 145 may contain a programmable processor which can be programmed to transmit data utilizing any of a number of encoding schemes which include, but are not limited to, Amplitude Shift Keying (ASK), Frequency Shift Keying (FSK), or Phase Shift Keying (PSK) or the combination of these techniques. The processor in the electronics module 145 may be programmed to alter the data encoding parameters based on surface transmitted pulses. The encoding parameters can include type of encoding scheme, baseline pulse amplitude, baseline frequency, or other parameters affecting the encoding of data.
The above described linear motor drive system provides precise control of the axial position of the poppet 103 with respect to the position of the main nozzle 125. Such precise control allows the improved use of several encoding schemes common to the art of mud pulse telemetry.
With the reciprocating spring balanced pulser system, the encoding or switching between phase, frequency, or amplitude does not require high actuation power, because the hydraulic forces are always balanced in any poppet position. Starting from the zero speed level a phase, frequency, or amplitude change does not substantially affect the overall power consumption, because the dynamic forces are zero at zero speed. In a embodiment, the main power is used to drive the system at a high frequency level. Once it is capable of creating a high frequency it can switch to another one almost immediately. This quick change gives a very high degree of freedom for encoding of telemetry data. The characteristic used for the encoding (frequency, phase or amplitude change) can be switched from one state to a second state, thereby transmitting information, within one period or less. No transition zone is needed between the different levels of encoded information. Hence there will be more information content per time frame in the pressure pulse signal of the reciprocating spring balanced pulser than with a conventional pulser.
An Amplitude Shift Key (ASK) signal can be easily generated with the reciprocating valve of the present invention. The signal amplitude is proportional to the amount of flow restriction and thus is proportional to the amount of linear motion, or travel, of the poppet 103 bringing it in proximity to the main nozzle 125. The poppet position can be continuously controlled and, therefore, the amplitude of each cycle can be different as the motor 104 can accurately move the poppet 103 through a different travel on each cycle according to programmed control from the electronics module 145.
In addition, because the poppet 103 can be continuously and accurately controlled, combinations of ASK and FSK or ASK and PSK may be used to encode and transmit multiple signals at the same time, greatly increasing the effective data rate.
Another embodiment of a reciprocating pulser is shown in
Flexible seal 702 is attached to shaft 703 and to an end surface of housing 704 and effects a seal between the wellbore fluid and lubricant 715. The flexible nature of seal 702 accommodates the repeated extension and retraction of poppet 713. Flexible seal 702 is similar in function and material to seal 107 previously described. Alternatively, lip seal 714 is used to seal between downhole fluid and lubricant 715.
In one embodiment, motor 718 is a controllable brushless DC motor. Such motors and their associated motor controllers, and/or control circuits, are commercially available, and/or known in the art, and are not described in detail here. Alternatively, motor 718 is a stepper motor. Again, such motors and their associated motor controllers, and/or control circuits are commercially available, and/or known in the art, and are not described in detail here. Such motors and controllers, as used herein, provide essentially continuous, precise control of the axial position of poppet 713 and its relative position to nozzle 712. This continuous precise control provides the ability to control various operating characteristics of interest of the generated pulses. These characteristics of interest include, but are not limited to, pulse amplitude, pulse frequency, pulse duration, and pulse phase with respect to a reference phase. Alternatively, a gear drive 801, see FIGS. 9A,B, may be included on the output of motor 718 to increase the torque available to actuate the pulser. Gear drive 801 may be a planetary gear drive or any other suitable gear drive.
In one embodiment, a sensor (not separately shown) is integral with the motor and provides a signal that can be used to relate the motor rotation to the position of poppet 713. In another embodiment, sensor 709, which may be an encoder, is external to motor 718 and produces a signal related to the rotation of motor shaft 717. Such encoders are commercially available and not described in detail herein. As shown in
Module 719 provides a housing suitable for location of electronic circuits and components for controlling the pulser operation. Contained in module 719 is a pulser controller 721 (see
Sensor 710 is located above orifice 712 and detects the generated pressure signals. In one embodiment, sensor 710 is a dynamic pressure sensor. Such sensors do not detect long term static changes in system pressure, but rather detect the pressure pulsations such as those generated by the present invention. Such dynamic pressure sensors are commercially available. In one embodiment, the dynamic pressure sensor is a hydrophone. Alternatively, sensor 710 may be a flow sensor that detects flow changes related to the downhole generated pressure fluctuations.
The sensed pressure signals detected by sensor 710 may be used by controller 721 in a feedback loop to adjust the motion of poppet 713 to produce a desired pulse characteristic, such as, for example, a desired magnitude, also called pulse amplitude. In addition, sensor 710 may be used to control and/or alter pulse shape, pulse duration, pulse frequency, pulse phase, and/or combinations of these parameters to transmit data. In one embodiment, the downhole pulser 700 acts autonomously to control pulse characteristics and encoding techniques based on instructions programmed into controller 721 prior to deployment.
In another embodiment, sensor 710 is used to detect signals sent from the surface to the downhole system. The signals from the surface are encoded pressure pulses containing information to provide commands and/or instructions to controller 721 to alter pulse characteristics, encoding techniques, and operational characteristics of the sensor modules 17, 20, 22. The information from the surface may direct controller 721 to change a particular pulse characteristic. Alternatively, the information may direct the controller to initiate a preprogrammed sequence of changes, for example, to step through a predetermined sequence of pulse frequencies in order to improve surface detection. Additional information may then be transmitted from the surface to specifically set the frequency that provided the best surface reception.
In another embodiment, a combination of normally autonomous control and operation may be used. For example, autonomous downhole operation may be overridden by downlinked surface information, as previously described.
While the downlinked information has been previously described as pressure and/or flow pulsations, any downlinking techniques known in the art may be used with the present invention. These include, but are not limited to: changes in drill string rotation; drilling fluid flow indicated by changes in RPM of the turbine-alternator; and starting and stopping of surface pumps as detected, for example, by the output of the turbine-alternator. In addition, the downlinked information may contain instructions for the operation and control of other tools in BHA 10, such as, for example, tools (not separately shown) for adjusting and or controlling the drilling direction of BHA 10.
In another embodiment, shown in FIGS. 9A,B, a compression spring 805 is positioned in housing extension 804 and is captured between shoulder 802 and retainer 806 attached to shaft 803. Spring 805 is in a preloaded condition when poppet 713 is in the open, also called the retracted position, as shown in
Magnetic spring 900, see
It is to be understood that all of the pulsers described herein are capable of providing precise position control of a poppet with respect to a nozzle to generate pulses. The precise control allows the pulser to use any of the encoding techniques, such as ASK, FSK, PSK, and combinations thereof, as described herein.
The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible. It is intended that the following claims be interpreted to embrace all such modifications and changes.
|Cited Patent||Filing date||Publication date||Applicant||Title|
|US2759143||Jul 14, 1954||Aug 14, 1956||Arps Jan J||Earth borehole investigation-signaling system|
|US3065416||Mar 21, 1960||Nov 20, 1962||Dresser Ind||Well apparatus|
|US3741321||May 20, 1971||Jun 26, 1973||Brady J||Means to prevent inward leakage across seals in a well tool|
|US3764968||Jun 15, 1972||Oct 9, 1973||Schlumberger Technology Corp||Well bore data transmission apparatus with debris clearing apparatus|
|US3958217||May 10, 1974||May 18, 1976||Teleco Inc.||Pilot operated mud-pulse valve|
|US4215427||Feb 27, 1978||Jul 29, 1980||Sangamo Weston, Inc.||Carrier tracking apparatus and method for a logging-while-drilling system|
|US4266606||Aug 27, 1979||May 12, 1981||Teleco Oilfield Services Inc.||Hydraulic circuit for borehole telemetry apparatus|
|US4351037||Jan 10, 1980||Sep 21, 1982||Scherbatskoy Serge Alexander||Systems, apparatus and methods for measuring while drilling|
|US4519574||Aug 1, 1983||May 28, 1985||Norton Christensen, Inc.||Auxiliary controlled valve disposed in a drilling string|
|US4802150||Aug 24, 1981||Jan 31, 1989||Nl Sperry Sun, Inc.||Mud pressure control system with magnetic torque transfer|
|US4901290||May 9, 1988||Feb 13, 1990||Eastman Christensen Company||Apparatus for the generation of pressure pulses in drilling mud compositions|
|US4953595||May 10, 1989||Sep 4, 1990||Eastman Christensen Company||Mud pulse valve and method of valving in a mud flow for sharper rise and fall times, faster data pulse rates, and longer lifetime of the mud pulse valve|
|US5055837||Sep 10, 1990||Oct 8, 1991||Teleco Oilfield Services Inc.||Analysis and identification of a drilling fluid column based on decoding of measurement-while-drilling signals|
|US5079750||Jun 13, 1990||Jan 7, 1992||Scherbatskoy Serge Alexander||Method and apparatus for transmitting information in a borehole employing discrimination|
|US5103430||Nov 1, 1990||Apr 7, 1992||The Bob Fournet Company||Mud pulse pressure signal generator|
|US5115415||Mar 6, 1991||May 19, 1992||Baker Hughes Incorporated||Stepper motor driven negative pressure pulse generator|
|US5473579||Oct 25, 1993||Dec 5, 1995||Ronald L. Shaw||Well bore communication pulser|
|US5583827||Jul 23, 1993||Dec 10, 1996||Halliburton Company||Measurement-while-drilling system and method|
|US5586084||Dec 20, 1994||Dec 17, 1996||Halliburton Company||Mud operated pulser|
|US5787052 *||Jun 7, 1995||Jul 28, 1998||Halliburton Energy Services Inc.||Snap action rotary pulser|
|US5802011||Oct 4, 1995||Sep 1, 1998||Amoco Corporation||Pressure signalling for fluidic media|
|US5836353||Sep 11, 1996||Nov 17, 1998||Scientific Drilling International, Inc.||Valve assembly for borehole telemetry in drilling fluid|
|US6002643 *||Aug 19, 1997||Dec 14, 1999||Computalog Limited||Pulser|
|US6097310||Jan 8, 1999||Aug 1, 2000||Baker Hughes Incorporated||Method and apparatus for mud pulse telemetry in underbalanced drilling systems|
|US6469637||Aug 12, 1999||Oct 22, 2002||Baker Hughes Incorporated||Adjustable shear valve mud pulser and controls therefor|
|US6626253||Feb 27, 2001||Sep 30, 2003||Baker Hughes Incorporated||Oscillating shear valve for mud pulse telemetry|
|US6898150 *||Mar 12, 2002||May 24, 2005||Baker Hughes Incorporated||Hydraulically balanced reciprocating pulser valve for mud pulse telemetry|
|US20040069535||Aug 11, 2003||Apr 15, 2004||Baker Hughes Incorporated||Method for generating pressure fluctuations in a flowing fluid|
|EP0617196A2||Mar 23, 1994||Sep 28, 1994||Halliburton Company||Digital mud pulse telemetry system|
|GB2250320A||Title not available|
|WO2002072993A2||Mar 13, 2002||Sep 19, 2002||Baker Hughes Inc||Hydraulically balanced reciprocating pulser valve for mud pulse telemetry|
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US7881155 *||Jan 11, 2010||Feb 1, 2011||Welltronics Applications LLC||Pressure release encoding system for communicating downhole information through a wellbore to a surface location|
|US8162078||Jun 29, 2009||Apr 24, 2012||Ct Energy Ltd.||Vibrating downhole tool|
|US8166992 *||Sep 25, 2007||May 1, 2012||Wavefront Reservoir Technologies Ltd.||Placement of fluids in ground by pulse-injection|
|US8424596 *||Nov 1, 2010||Apr 23, 2013||Robert Douglas Bebb||High efficiency fluid pumping apparatus and method|
|US8684093||Apr 21, 2011||Apr 1, 2014||Bench Tree Group, Llc||Electromechanical actuator apparatus and method for down-hole tools|
|US8824241||Jan 31, 2011||Sep 2, 2014||David CLOSE||Method for a pressure release encoding system for communicating downhole information through a wellbore to a surface location|
|US8917575 *||Feb 22, 2012||Dec 23, 2014||Baker Hughes Incorporated||Device for generating pressure pulses in flowing fluid and method for the same|
|US9013957 *||Feb 7, 2012||Apr 21, 2015||Teledrill, Inc.||Full flow pulser for measurement while drilling (MWD) device|
|US9038735||Mar 28, 2014||May 26, 2015||Bench Tree Group LLC||Electromechanical actuator apparatus and method for down-hole tools|
|US9091143||Mar 28, 2014||Jul 28, 2015||Bench Tree Group LLC||Electromechanical actuator apparatus and method for down-hole tools|
|US20090114396 *||Nov 5, 2007||May 7, 2009||David John Kusko||Wellsite measurement and control while producing device|
|US20110100623 *||May 5, 2011||Robert Douglas Bebb||High efficiency fluid pumping apparatus and method|
|US20110174500 *||Oct 29, 2008||Jul 21, 2011||Mark Davies||Connecting assembly|
|US20120312540 *||Feb 21, 2011||Dec 13, 2012||Lance Leo Lefebvre||Magnets-based tool for pulsing injected liquid|
|US20130051177 *||Feb 7, 2012||Feb 28, 2013||Teledrill, Inc.||Full Flow Pulser for Measurement While Drilling (MWD) Device|
|US20130215718 *||Feb 22, 2012||Aug 22, 2013||Baker Hughes Incorporated||Device for generating pressure pulses in flowing fluid and method for the same|
|WO2012094242A2 *||Dec 30, 2011||Jul 12, 2012||Welltronics Applications LLC||Method for a pressure release encoding system for communicating downhole information through a wellbore to a surface location|
|U.S. Classification||367/85, 175/40, 367/83, 367/81|
|International Classification||E21B47/18, H04L1/00, H04L27/00|
|Cooperative Classification||E21B47/187, H04L27/18, H04L27/0008, E21B47/182, H04L1/0001, H04L27/10, H04L27/02|
|European Classification||H04L27/02, H04L27/10, H04L27/18, E21B47/18P, E21B47/18C, H04L1/00A, H04L27/00F|
|Aug 4, 2005||AS||Assignment|
Owner name: BAKER HUGHES INCORPORATED, TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:HAHN, DETLEF;PETERS, VOLKER;ROUATBI, CEDRIC;AND OTHERS;REEL/FRAME:016611/0407;SIGNING DATES FROM 20050714 TO 20050718
|Sep 23, 2011||FPAY||Fee payment|
Year of fee payment: 4